Wednesday, July 15, 2015

Cost of solar power (54)


Yesterday I blogged about the DeGrussa mine PV/battery installation.  I made a few simple estimates about costs, but omitted to make an estimate of the Levelised Cost of Electricity.  That’s what I’ll provide today.


The cost of the DeGrussa project is clearly stated – AUD 40 million.  That buys a PV system with 10.6 MW peak power, one-axis tracking, and a battery installation that delivers 6 MW power for an unspecified amount of time. 


I can estimate the annual output of the DeGrussa installation from the diesel fuel usage that has been avoided.  It’s stated to be 5 million litres of fuel, thereby abating 12,000 t of CO2 emissions per year.


Here are the relevant properties of diesel fuel (data source):
  • density: 0.832 kg/litre
  • carbon content: 86.1%
  • energy density: 35.9 MJ/litre
So 5 million litres of diesel fuel contains 179.5 × 10^12 J of chemical energy.  If the diesel engine is 38% efficient, that would give 68.2 × 10^12 J = 18,947 MWh of electrical energy.


[To check the numbers, the 5 million litres of diesel would give rise to 5 × 10^6 × 0.832 × 0.861 × 44/12 kg of CO2, which I make to be 13,133 t CO2.  Not a perfect match with the 12,000 t of CO2 abatement that is claimed in the media releases, but good enough.]


I now proceed to calculate the Levelised Cost of Electricity using my standard assumptions:

  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.
For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for the DeGrussa installation are as follows:

Cost per peak Watt              AUD 3.77/Wp
LCOE                                     AUD 240/MWh

The components of the LCOE are:
Capital           {0.094 × AUD 40×106}/{18,947 MWhr} = AUD 198/MWhr
O&M              {0.020 × AUD 40×106}/{18,947 MWhr} = AUD 42/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:
(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan & Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)
(48)      USD 110 (Amanecer, PV, June 2014)
(49)      USD 113 (DEWA, PV, April 2016)
(50)      USD 284 (Ashalim, solar thermal, 2017)
(51)      USD 256 (Xina Solar One, solar thermal, 2017)
(52)      AUD 129 (Barcaldine, PV, one-axis, March 2017)
(53)      AUD 139 (Nyngan & Broken Hill, fixed PV, late 2015)
(54)      AUD 240 (DeGrussa, PV/batteries, early 2016)

Conclusion

You can compare results with my LCOE graphic.

On these numbers, the LCOE for the DeGrussa installation is quite expensive.  A solar thermal installation for comparison is Cerro Dominador, number 41 on the list above.  That has 110 MW peak power output from a heliostat/tower configuration with dry condensers, 17.5 hours thermal storage in molten salt, and an alleged Capacity Factor of 95%.  I calculated the LCOE for Cerro Dominador to be USD 125 per MWh (details). 

I calculate the Capacity Factor for DeGrussa to be 18,947/(10.6 × 24 × 365) = 0.204, which is not at all high for a system with one-axis tracking and a good solar resource.  With PV panels, the Capacity Factor is not improved by inclusion of storage, which is a major difference to solar thermal power generation with thermal storage.

We should of course make allowance for the fact that the Australian dollar is falling, currently at 0.743 USD.   Even so, the estimated LCOE for DeGrussa is perhaps 30% more than I expected.

Tuesday, July 14, 2015

DeGrussa mine installation


Big announcement today!

Sandfire Resources NL, an Australian mining company, has taken the plunge and invested in a major PV installation with battery storage at its DeGrussa copper and gold mine.  This project will set new worldwide benchmarks for integration of renewable energy into mining operations.

In this post, I’ll do a little detective work to look behind the media reports that are available here.  (At the link, you’ll find reports from ARENA, CEFC, juwi, Neoen, OTOC and Sandfire Resources.)

But first, some facts.  The DeGrussa mine is remote (900 km from Perth) and currently served by a 19 MW diesel generator.  The new PV installation will be integrated seamlessly with the existing diesel plant; it will have peak capacity 10.6 MW with “short-term” battery storage to deliver 6 MW.  There will be 34,080 PV panels with single-axis tracking installed on a 20 Ha site.  The project will be complete in early 2016.  Each year, the installation will offset 5 million litres of diesel fuel usage and 12,000 t CO2 emissions.

The actual owner of the project is Neoen, a French renewable energy firm.  juwi Renewable Energy Pty Ltd will develop and operate the project, with OTOC Ltd responsible for procurement and construction.  Sandfire Resources will purchase the electricity “at a fixed rate that is lower than the historical cost of diesel-generated power”.

The project is financed by CEFC (debt, AUD 15 million), ARENA (grant, AUD 20.9 million) and equity (mainly from Neoen, “less than $1 million” from Sandfire Resources).  The total project cost is AUD 40 million.

We all know about the trend with PV prices – namely down, with an experience curve that shows 22% price reduction in module costs per doubling of global installed capacity.  That trend has been in place for more than 30 years.  Data is also starting to emerge about the cost of battery storage, see for example my blog post on recently published data.

What can we infer about the cost of the batteries?

Let’s work backwards from an estimate for the cost of the PV component.  According to my recent analysis of the Nyngan & Broken Hill project, the capital cost there was AUD 2.84 per peak Watt.  At the same capital cost, the PV component of the DeGrussa project would be AUD 10.6 × 10^6 × 2.84 = AUD 30.1 million.

That leaves AUD 9.9 million for the battery component, which is to deliver a peak power of 6 MW.  If the “short term” storage is for 1 hour, the battery storage is priced at AUD 9.9 × 10^6 /6,000 kWh = AUD 1,650 per kWh.  If the storage is for 2 hours, the cost is AUD 9.9 × 10^6 /12,000 kWh = AUD 825 per kWh.  For 3 hours it would be AUD 9.9 × 10^6 /18,000 kWh = AUD 550 per kWh.  You can make your own calculation based on your interpretation of “short term”.

Presumably other companies bid for the DeGrussa project, amongst them companies using Concentrated Solar Thermal power generation with storage.  So, it’s interesting that PV/battery technology has won the contract.

The other salient feature that emerges from the media reports is that this is a big market segment.  According to ARENA’s media release, “remote industries in Australia currently rely on 1.2 GW of power from diesel fuel”.  Based on the price tag for the DeGrussa mine, I estimate the market niche to be AUD 1.2 × 10^9 × 40 × 10^6 / (10.6 × 10^6) = AUD 4.5 billion.  Worth pursuing, and perhaps the DeGrussa project represents a pivotal moment.

Whatever, I congratulate all those involved in this development.


Note added one day later: 
I was also able to make an estimate for the Levelised Cost of Electricity for the DeGrussa installation.  See www.sunoba.blogspot.com, post for 16 July 2015.

Wednesday, July 8, 2015

Cost of solar heating (1)


RenewEconomy has an interesting story today about a planned solar thermal installation in Oman.  The project name is Miraah, which is Arabic for mirror.  Other sources with details of the Miraah project are here (WSJ) and here (the California-based project developers, GlassPoint).

But Miraah is not for power generation, rather for process heat in the form of steam to be used for enhanced oil recovery.  In brief this involves forcing steam into an oil field so that heavy oil is easier to extract.  At present, the operator of the oil field generates necessary steam from natural gas, so the solar project will free up 5.6 trillion BTU (5.9 billion MJ) of natural gas per year for other use.  If those other uses don’t involve combustion of the natural gas or other release of CO2, then CO2 emissions of 300,000 tons per year would be abated.

The cost of the Miraah project is reported as USD 600 million for a power output of 1,021 MW thermal.  The area of the plant is 3.0 km^2 and 6,000 tons of steam will be produced per day.

The Miraah technology involves parabolic trough mirrors with one-axis tracking.  Steam will be generated directly.  The only unusual feature about the installation is that the parabolic troughs will be deployed inside 36 large glasshouses, which will be used to shelter the mirrors from harsh desert conditions.  That way, the mirrors, presumably the most expensive component of the installation, do not have to be as robust as otherwise.

What can we say about the cost of this heat collection system?  Here’s a back-of-the-envelope calculation …

Suppose the efficiency of heat collection is 65% and that peak insolation is 1 kWth/m^2.  Then the area of the mirrors is 1,021,000 kW/(1kW/m^2 * 0.65) = 1,570,769 m^2.  The cost of the project is USD 600 million, which equates to 600,000,000/1,570,769 = USD 382/m^2.


Another useful metric is the cost per GJ.  Using my normal methodology for calculating CAPEX plus OPEX (see any post entitled “cost of solar power” on this blog), I estimate USD 600 × 106 × (0.094+0.02)/ (5.9 × 106 GJ) = USD 11.6/GJ.  More expensive than natural gas, but maybe the Omani investors have a cheaper cost of capital than the 8% on which my estimate is based. 


None of the press reports that I saw mention the collection temperature, but let's say they want an operating steam pressure of 20 bar (2.0 MPa), at which pressure the boiling point is 212°C.


This project is remote (800 km from the nearest town and 160 km from the Yemen border), so construction costs would not be the cheapest on the planet.  Still, at USD 382 per square metre, the cost of the plant does seem rather high.  I’ve heard lots of enthusiastic solar thermal proponents talking about costs of around USD 100 per square metre.

I’m left pondering the question – what is world-best cost (USD per square metre) for large-scale solar heating?

Monday, June 15, 2015

Cost of solar power (53)


In recent weeks, a large PV plant in Australia at Nyngan has come online and a companion plant at Broken Hill is slated for completion later this year.  I blogged about these plants in 2012 (link), so I thought it might be useful to revisit the post to see if expectations were met.

First, some information sources:

The plants are being built for AGL, a large Australian energy utility.  The overall project cost for both plants will be AUD 440 million, supported by funding of AUD 166.7 million from ARENA (Australian Renewable Energy Agency) and AUD 64.9 million from the NSW Government.

 
The installations will use thin film panels from First Solar fixed at a 25° tilt.  The total capacity of the two plants is 155 MW grid AC (Nyngan 102 MW, Broken Hill 53 MW).   Nyngan has a 250 Ha footprint, whilst that for Broken Hill is 140 Ha.

 
Construction has been quick.  Nyngan was commissioned in June 2015 after construction started in January 2014, whilst Broken Hill is due to be completed in November 2015, after construction started in July 2014 and first panels were installed in January 2015.

 
The annual output caused me trouble in 2012.  It was stated to be 365 GWh per year from a plant with peak power 159 MW.  That gave a Capacity Factor of 365,000/(159 × 365 × 24) = 0.265.   Based on other projects I had studied, I thought the Capacity Factor was too high, and for my estimate I used a Capacity Factor of 0.18.

 
Now the as-built plants have peak power 155 MW and the annual output is said to be 360,000 MWh, corresponding to a Capacity Factor of 360,000/(155 × 365 × 24) = 0.265.  Exactly the same Capacity Factor as in 2012!

 
It still seems high to me for fixed panels.  Admittedly the solar resource at Nyngan and Broken Hill at latitude 31-32°C is good.  But the resource at the Barcaldine Solar Farm at latitude 23.5° is better (see here for an insolation chart) and their panels will have one-axis tracking.  Barcaldine has a Capacity Factor of 0.256 (details here).

 
Reluctantly I’ll accept First Solar’s CF and proceed to calculate the Levelised Cost of Electricity using my standard assumptions:

  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.
For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The revised results for Nyngan and Broken Hill (combined) are as follows:

Cost per peak Watt              AUD 2.84/Wp
LCOE                                     AUD 139/MWh

The components of the LCOE are:

Capital           {0.094 × AUD 440×106}/{360,000 MWhr} = AUD 115/MWhr
O&M              {0.020 × AUD 440×106}/{360,000 MWhr} = AUD 24/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

 

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan & Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)
(48)      USD 110 (Amanecer, PV, June 2014
(49)      USD 113 (DEWA, PV, April 2016)
(50)      USD 284 (Ashalim, solar thermal, 2017)
(51)      USD 256 (Xina Solar One, solar thermal, 2017)
(52)      AUD 129 (Barcaldine, PV, one-axis, March 2017)
(53)      AUD 139 (Nyngan & Broken Hill, fixed PV, late 2015)

Conclusion

You can compare results with my LCOE graphic.

I’m suspicious of the claimed Capacity Factor for the Nyngan and Broken Hill plants.  On their data, which I reluctantly accept, the LCOE is 23% more than leading results in recent time (Amanecer, DEWA) and about 8% more than planned for the Barcaldine installation.

I really welcome these utility installations in Australia.  My spirits would be even brighter if we could get a big solar thermal CSP plant built.  I’m working on my plans J

Wednesday, May 20, 2015

Sustainability Drinks


There’s a lively group called “Sustainability Drinks” in Sydney.  They meet monthly and hear a few short presentations from people working in the sustainability industry.  I was an invited speaker last night, and this is what I said to the audience of around 120 people …
 
My name is Noel Barton, although on Fridays I call myself Geoff.  That’s a complicated story I can explain later.
 
I was originally an applied mathematician, finishing my studies with a PhD at the University of Western Australia in 1973.  I had a post-doctoral scholarship at the University of Cambridge (UK), then teaching stints at the University of Queensland and University of NSW (1975-81).  From 1981 to 2003 I worked for CSIRO, where I had a varied and good career, initially as a researcher and subsequently as leader of CSIRO’s applied mathematicians for a dozen years.  The job involved industrial applications of mathematics, a concept that occupied me for two decades.
 
I was also Director of the 5th International Congress on Industrial and Applied Mathematics, held in Sydney in 2003.  The event, the biggest mathematical conference ever held in Australia, attracted about 1900 registrations.  As a result, I’m an Ambassador of Business Events Sydney, the group with responsibility to attract conferences and exhibitions to Sydney.  That’s a big business.
 
In 2003, at age 55, I came to a point of career renewal.  Should I re-invent myself inside CSIRO?  Or break out?  As it happened, my children were fully educated and independent, and I’d had a nasty health scare a couple of years earlier.  I was able to take an early retirement option and follow my passion, which was to become an inventor, mainly in new concepts for solar thermal power generation.
 
There’s a very nice book about happiness written by Martin Seligman – you look for pleasure and gratification at the basic level (well I already had that!), then move on to exercise of your strengths and virtues (my inventive and mathematical skills) and finally to meaning and purpose (doing something worthwhile).  So the role of an inventor in solar energy really appealed.
 
I set up my own business, Sunoba Pty Ltd.  In 2004 I invented and subsequently patented a completely new thermodynamic cycle for power generation; it’s based on evaporative cooling of hot air at reduced pressure.  I made a theoretical analysis of the concept and built an experimental engine to verify the theory.  But my experimental engine had a terrible operating mechanism and I had no funds for development of the improved mechanism I’d invented.  I spent several years looking for investors, but wasn’t able to convince anyone that the engine was worthwhile.  And, to be honest, the engine was big, under-powered and needed lots of water for operation.
 
Eventually I abandoned work on the evaporation engine.  I now regard the episode as an excellent learning experience, but you might hear me wince with pain as I relate the story!
 
ll was not lost however.  As part of my research program I’d been working on storage of solar thermal energy in pebble beds.  I realised that a form of the Brayton-cycle engine could be integrated with pebble bed storage to give a very promising concept for solar thermal power generation.  The expected Levelised Cost of Electricity was good, there was storage for operation after dark and the possibility for co-firing with other fuels.
 
That’s my current focus, and it’s still looking good a few years later.  With the assistance of investors, I hope to carry out experiments on a small engine later this year.  If the tests are successful, we’ll move on to bigger things.
 
We all know about the rapid growth of PV.  Some argue that solar thermal power generation will be killed off by PV together with new forms of battery storage.  I don’t agree with that.  Solar thermal power generation has excellent storage capabilities and allows for co-firing so as to give on-demand despatchable power, even when the sun doesn’t shine and the wind doesn’t blow for weeks at a time.  I think those attributes will find a place in the 100% renewable energy systems of the future. 
 
In any case, I have a wise inventor friend who says you don’t have to save the world – just find a profitable solution in one tiny niche of the world’s vast energy system!
 
I’m always happy to have conversations about solar thermal power generation, just get in touch.
 
I’ll finish with two remarks:
 
I’m currently Convenor of the Sydney Central Chapter of the Australian Solar Council.  Our main activity is to hold Information Evenings on the 4th Tuesday of each month and we’re always looking for speakers.  Just get in touch with me if you would like to attend or speak.
 
Finally, I run a blog, which you can see at www.sunoba.blogspot.com.  In trying to attract investors for a new invention in power generation, you always get the same questions:
  • What is this technology?
  • How well does it work?
  • How much does it cost?
  • How does it compare to other technologies?
 
I needed to answer those questions, so I started to collect information on the cost of solar projects.  I have now analysed the LCOE for 52 solar projects worldwide.  The blog also analyses a couple of tidal projects and one geothermal project.  The database and results are available to all, just visit the blog, www.sunoba.blogspot.com.


You'll also see other quirky things there, such as when our fossil fuels will run out, the real cost of coal-fired power, life-cycle analyses for batteries, the cost of battery storage, beyond-Carnot heat pumps, and my favourite – if you burn 1 kg of coal, how much heat will be trapped by CO2 in the earth’s atmosphere?  And how does that compare to the heat generated by combustion?